Field of the Invention
This application is directed to an anchor system for production tubing in a pumpjack type oil well. The anchor stabilizes the tubing during operation of the well as explained below.
Description of Related Arts Invention
A pumpjack is often used with a “rod pumping system” and is used to mechanically lift liquid out of the well if there is not enough bottom hole pressure for the liquid to flow all the way to the surface. The arrangement is commonly used for onshore wells to enhance or increase production. Pumpjacks are common in oil-rich areas. Depending on the size of the pump, it generally produces 5 to 40 liters of liquid at each stroke. Often this is an emulsion of crude oil and water. Pump size is also determined by the depth and weight of the oil to remove, with deeper extraction requiring more power to move the increased weight of the discharge column (discharge head). A pumpjack converts the rotary mechanism of a motor to a vertical reciprocating motion to drive the pump shaft, and is exhibited in the characteristic nodding motion. The engineering term for this type of mechanism is a walking beam. The prime mover of the pumpjack runs a set of pulleys to the transmission which drives a pair of cranks, generally with counterweights on them to assist the motor in lifting the heavy string rods. The cranks raise and lower one end to assist the motor in lifting the heavy string rods. The cranks raise and lower one end of an I-beam which is free to move on an A-frame. On the other end of the beam, there is a curved metal box called a horse head or donkey head. A cable made of steel or fiberglass, called a bridle, connects the horse head to a polished rod, a piston that passes through a stuffing box. The polished rod has a close fit to the stuffing box, letting it move in and out of the production tubing without fluid escaping. The bridle follows the curve of the horse head as it lowers and raise to create a nearly vertical stroke. The polished rod is connected to a long string of rods called sucker rods, which run through the tubing to the down-hole pump, usually positioned near the bottom of the well. At the bottom of the tubing is the down-hole pump comprised of two assemblies. This pump has two ball check valves: the first is a stationary valve at bottom called the standing valve. The second is in valve on the piston connected to the bottom of the sucker rods that travels up and down as the rods reciprocate, known as the travelling valve. Each of these valves permits wellbore liquids to move upward toward the surface but prohibits fluids from moving back downhole. Reservoir fluid enters from the formation into the bottom of the borehole through perforations that have been made through the casing and cement. When the rods at the pump end are traveling up, the traveling valve is closed and the standing valve is open due to the drop pressure in the pump barrel. Consequently, the pump barrel fills with the fluid from the formation as the traveling piston lift the previous contents of the barrel upwards. When the rods begin pushing down, the traveling valve opens and the standing valve closes due to an increase in pressure in the pump barrel. The traveling valve drops through the fluid in the barrel. The piston then reaches the end of its stroke and begins its path upward again, repeating the process. The number of strokes per time unit defines the maximum flow rate from the well. However each application affects the fill efficiency of this volume, which in turn, affects the actual flow rate of fluids from the well. Affecting efficiency is the elasticity of the tubing, wherein the tubing “stretches” axially in tension during down stokes and “compresses” or buckles axially during upstrokes. When “heavy oil” is produced by rod pumped wells often steam is injected in the well to reduce the viscosity of the hydrocarbons, enabling it to flow more readily into the wellbore. Cycling between steam injection periods and production periods, thermal effects cause the steel tubing to either expand lengthwise with heat or contract as the well cools, which also affects the efficiency of the well. A well-known tubing anchor that serves to stabilizing the tubing may be employed, but the thermal effects of steam injection cause very high alternating compression and tension loads on the tubing anchor also causing bucking and tension in the production tubing further decreasing pumping efficiency and often leading to premature failure of the tubing anchor. The great temperature variations imposed by steam injection prohibit use of any known tubing anchor.
Consequently, there is a need for an anchoring system that prevents a wide variation of the tubing movement caused by up and down strokes of the sucher rods, and the expansion and contraction of the tubing during heating and cooling cycles both in an axial and radical direction.